Apparatus and method relating to managed pressure drilling (mpd) whilst using a subsea rcd system

ABSTRACT

A subsea rotating control device (RCD) system ( 1; 2 ) adapted to permit a tubular work string to pass there through such that there is an annulus created between the inner throughbore of subsea rotating control device (RCD) system ( 1; 2 ) and the outer surface of the tubular work string. 
     The subsea rotating control device (RCD) system ( 1; 2 ) comprises a system housing ( 10 ) comprising a throughbore, an upper end and a lower end ( 10 L) adapted for connection with a BOP ( 18 ) of a wellhead. 
     The subsea RCD system ( 1; 2 ) further comprises at least two RCD seals ( 302, 2302; 304, 2304 ) arranged for selective mounting within the system housing ( 10 ) and which are selectively actuable between an unsealed configuration and a sealed configuration.

The present invention relates to an apparatus and method relating to subsea managed pressure drilling and in particular relates to a subsea managed pressure drilling (MPD) rotating control device (RCD) system incorporating at least one annular seal.

BACKGROUND OF THE INVENTION

When drilling for offshore hydrocarbons, some target reservoirs are located in difficult formations such as clastic, carbonate or pre-salt formations. Such formations typically require Managed Pressure Drilling (MPD).

In a traditional MPD system the drill string is run through a riser. The pressure of the returning drilling fluid is controlled within the annulus between the outside of the drill string and the inner bore of the riser. When drilling in deep water, the volume of drilling mud is significant due to the requirement for a larger riser. This leads to the need for a larger drill rig to support the riser.

The weight of the large column of mud produces high hydrostatic pressures, which result in the need for numerous casing points in areas of the formation where high pore pressures and low fracture gradients exist. Numerous casing points require a large subsea wellhead.

A main feature of an MPD system is a Rotating Control Device (RCD). An RCD permits passage of the drill string through the riser and creates a seal between them, while permitting rotation of the drill string. The RCD therefore prevents pressurised drilling fluid from escaping to the environment.

A traditional RCD system is housed within the riser and therefore a traditional RCD system still requires the riser.

The drilling fluid is typically pumped down the drill string and exists the bottom of the drill string through the BHA and the drill bit and returns up the annulus between the outside of the drill string and the inside of the riser. Deep water MPD systems typically include an integration joint which typically consists of three or more components all connected in line in the riser system. These three components typically comprise an annular seal within a separate tubular and an RCD located above the annular seal within its own separate tubular, where the integration joint is located in line/in series within the riser string above an MPD flow spool and below a telescopic joint. The RCD, the annular seal and the MPD flow spool along with the other components in the riser system all act together to enable closed loop drilling in deep water environments.

The RCD typically comprises an upper and a lower cup shaped rubber seal which is rotatable with respect to the integration joint and which can therefore rotate with the drill string as it is rotated from surface, where the pair of rotatable RCD rubber seals permit passage of the drill string through the riser but also seal around the drill string whilst permitting rotation of it thereby preventing pressurised drilling fluid from passing further up the annulus in the riser string. Accordingly, the RCD forces the returning drilling fluid to flow out of the annulus in the riser string and through goose necks provided at each side of the MPD flow spool where the goose necks are attached to drilling fluid return hoses.

Additional information and drawings regarding conventional integrated MPD systems can be read in Volume 76, Issue 10 of Offshore magazine and at the time of writing an online version is available at:—https://www.offshore-mag.com/article/print/volume-76/issue-10/drilling-and-completion/integrated-mpd-system-aids-drilling-operation-offshore-brazil.html

It is an object of the present invention to eliminate or ameliorate some or all of the above-noted disadvantages of conventional (riser based) drilling, arising when drilling in deep water with the aim of providing a Subsea RCD which is connected directly or indirectly (typically via a flexible connector) to the Subsea BOP resulting in riserless drilling.

SUMMARY OF THE INVENTION

According to a first aspect of the present invention there is provided a subsea rotating control device (RCD) system adapted to permit a tubular work string to pass there through such that there is an annulus created between the inner throughbore of subsea rotating control device (RCD) system and the outer surface of the tubular work string, the subsea rotating control device (RCD) system comprising:—

a system housing comprising a throughbore;

an upper end; and

a lower end adapted for connection with a BOP of a wellhead;

and the subsea RCD system further comprising:—

at least two RCD seals arranged for selective mounting within the system housing and which are selectively actuable between an unsealed configuration in which the at least two RCD seals are radially outwardly retracted and a sealed configuration in which the at least two RCD seals are radially inwardly extended; and

at least one annular seal arranged for selective mounting within the system housing below the at least two RCD seals, wherein the said at least one annular seal is selectively actuable between an unsealed configuration in which the said at least one annular seal is radially outwardly retracted and a sealed configuration in which the said at least one annular seal is radially inwardly extended.

Preferably, the at least two RCD seals are inflatable such that they can be inflated into the sealed configuration and deflated into the unsealed configuration. Preferably, the at least one annular seal is inflatable such that it can be inflated into the sealed configuration and deflated into the unsealed configuration.

Preferably, the system housing comprises a wellbore fluid and/or drilling mud returns port which is preferably formed through a sidewall of the system housing. More preferably, a wellbore fluid and/or drilling mud returns hose may be connected to the said port. Preferably, the port permits wellbore fluid and/or drilling mud located in the throughbore of the subsea rotating control device (RCD) system to exit the throughbore and return to the surface and more preferably permits wellbore fluid and/or drilling mud located in the throughbore of the subsea rotating control device (RCD) system below the lowermost (or most upstream) of the at least two RCD seals and/or the at least one annular seal to exit the throughbore and return to the surface. Most preferably, the port is located below (or upstream of) the lowermost (or most upstream) of the at least two RCD seals and/or the at least one annular seal. Typically, the port permits wellbore fluid and/or drilling mud located in the throughbore of the subsea rotating control device (RCD) system and/or the BOP and wellhead below (or upstream of) the lowermost of the at least two RCD seals and/or the at least one annular seal to exit the throughbore and return to the surface via the returns hose whilst the two RCD seals and/or the at least one annular seal seal against the outer surface of the workstring at a location above (or downstream) of the port and as such prevent the wellbore fluid and/or drilling mud from escaping to the outer environment. Embodiments of the present invention have the advantage that, with the two RCD seals and/or the at least one annular seal sealing the annulus between the throughbore of the system housing and the outer surface of a work string (which is typically a drill string) and the wellbore fluid and/or drilling mud being returned to the surface via a separate hose, riserless but yet managed pressure drilling (without loss of any wellbore fluid and/or drilling mud to the outer subsea environment) can be achieved.

Preferably, the at least two RCD seals are capable of being locked within the throughbore by at least one locking device. Preferably, the at least one annular seal is capable of being locked within the throughbore by at least one locking device. More preferably, each of the at least two RCD seals and the at least one annular seal comprise their own respective locking device. Most preferably, each of the at least two RCD seals and the at least one annular seal can be separately and selectively locked and unlocked as required by actuation of their own respective locking device in such a manner to permit one of them to be locked within the throughbore and the other of them to be run into and/or retrieved from the throughbore of the system housing.

Preferably the subsea RCD system is for use in managed pressure drilling operations and typically the tubular work string is a drill string.

Typically, the at least two RCD seals and the at least one annular seal are adapted to be located within the throughbore of the system housing. Typically, the at least two RCD seals and the at least one annular seal are adapted in use to provide a seal within the said annulus.

Preferably, each of the said at least two RCD seals are provided within an RCD housing and more preferably, the said at least one annular seal is provided within a separate housing from that of the at least two RCD seals.

Preferably, the at least two RCD seals are rotateably mounted within said RCD housing by at least one bearing mechanism.

Typically, the said at least two RCD seals and the at least one annular seal is in the form of a cartridge assembly and preferably, each of the said at least two RCD seals and the at least one annular seal comprises a retrieval means to permit running in and/or retrieval of the respective each of the said at least two RCD seals and the said at least one annular seal.

Preferably, each said seal housing comprises a locking means into which a respective locking device can engage in order to lock said seal housing of said respective seal within the throughbore of the system housing. Said locking means may comprise a slot, groove or recess into which a locking device such as a locking dog may be inserted.

Preferably, each said locking device is mounted on the system housing. Preferably, each said locking device comprises one or more radially moveable dog members which can be moved radially inwardly to projecting inwardly from the inner diameter of the system housing and more preferably can be moved radially inwardly to projecting inwardly from the inner diameter of the system housing into the said locking means of the respective seal housing. Typically, each said locking device can be actuated between a radially inwardly projecting configuration and a retracted configuration such that they do not project into said locking means of the respective seal housing. Preferably, each said locking device is remotely actuatable (such as from the surface by an operator) between the radially inwardly projecting or locked configuration and the retracted or unlocked configuration, allowing for remote activation of each of the locking devices by the operator.

Preferably the said at least two RCD seals and the at least one said annular seal are adapted to be located co-axially within the throughbore of the system housing and more preferably the longitudinal length of the system housing is longer than the combined longitudinal length of the said at least two RCD seals and the said at least one annular seal more preferably the inner diameter of the system housing is greater than the outer diameter of each of the said at least two RCD seals such that the said at least two RCD seals are adapted to be wholly located co-axially within the system housing and most preferably the said at least two RCD seals are adapted to be wholly located co-axially within the throughbore of the system housing. Preferably, the system housing is adapted to be able to house both of a pair of rotation control device (RCD) seals and at least one annular seal within its throughbore, preferably in series/in line along its longitudinal length.

Preferably, at least one of the two RCD seals and the said annular seal device can be:—

i) run into the throughbore of the system housing, typically through an upper end of the system housing; and

ii) locked to the system housing within the throughbore of the system housing.

Preferably at least one of the said two RCD seals and the said annular seal are capable of being unlocked from and more preferably retrieved from the throughbore of the system housing, typically by pulling it upwards through the throughbore of the system housing and further pulling it upwards through the upper end of the system housing into the surrounding subsea environment on a workstring.

Preferably the at least two RCD seals are arranged to be located above the annular seal device within the throughbore of the system housing.

The at least two RCD seals may be retrieved and run into the throughbore on its own by a running/retrieval tool or alternatively, may be retrieved and run into the throughbore with at least one annular seal.

One or both of the at least two RCD seals and the at least one annular seal may be located within the throughbore of and locked to the system housing when the system housing is first installed on the BOP; or

one or both of the at least two RCD seals and the at least one annular seal may be retrieved from and/or run into the throughbore of the system housing through the throughbore of an upper end of the system housing and be locked to the system housing within the throughbore of the system housing after the system housing has been installed on the BOP.

Typically, suitable seals such as (but not limited to) O-ring seals, pressure activated seals or mechanically activated seals are provided to act between the outer surface of the at least two RCD seals and the inner throughbore of the system housing. Preferably said seals are provided on and/or around the outer circumferential surface of the at least two RCD seals such that they act to seal the gap between the outer surface of the at least two RCD seals and the inner throughbore of the system housing.

Additionally, further suitable seals such as (but not limited to) O-ring, pressure activated seals or mechanically activated seals are typically provided to act between the outer surface of the said at least one annular seal and the inner throughbore of the system housing. Preferably said seals are provided on and/or around the outer circumferential surface of the said at least one annular seal such that they act to seal the gap between the outer surface of the said at least one annular seal and the inner throughbore of the system housing.

Preferably the system housing comprises a seat or other formation formed on its inner throughbore preferably at a location on its inner diameter and which prevents the at least one annular seal from moving any lower through the system housing than said seat. Typically, the said seat is a formation formed on the inner diameter of the system housing and more preferably said formation comprises a narrower inner diameter load bearing shoulder than the outer diameter of at least a portion of the at least one annular seal such that the said portion seats upon said shoulder and thus any further downward movement of the at least one annular seal is arrested. Typically, the said formation comprises a narrower inner diameter load bearing shoulder than the outer diameter of at least a portion of the at least one annular seal. Alternatively, said seat or other formation comprises one or more radially moveable dog members which can be moved radially inwardly to provide a shoulder projecting inwardly from the inner diameter of the system housing for the said annular seal to seat upon in order to prevent the annular seal from moving any lower through the system housing than said shoulder or seat.

Typically, the at least two RCD seals comprise an outer RCD housing and two RCD seals which are rotatable with respect to the outer RCD housing. Typically, the two RCD seals further comprise one or more bearings to couple them to the RCD housing such that the two RCD seals are rotatable on the bearing with respect to the stationary outer RCD housing such that the said each respective RCD seal seals against and is rotatable with the work string (which is typically a drill string) which passes through the throughbore of the system housing. Preferably the at least two RCD seals are longitudinally spaced apart rotatable seals and further comprise an in use upper most RCD seal and a lowermost RCD seal.

Preferably each of the upper and lower RCD seals is formed from a resilient material such as rubber and/or polyurethane and which is inflatable such that when in an inflated state has an inner diameter which is a friction fit or comprises an inner diameter that matches the outer diameter of the drill string such that each of the upper and lower RCD seals are forded against the outer surface of the drill string and seals against the outer surface of the drill string such that it does not permit drilling fluid or other well fluids located in the annulus to pass through the throughbore of the two RCD seals in the upwards direction from downhole to up-hole when in the inflated state. Typically, the said two RCD seals comprise an in use de-energised or deflated inner diameter which is greater than the outer diameter of the drill string which passes there through such that when the said two RCD seals in use are de-energised, they allow the free movement of the drill string there through and therefore do not impede the movement there through and therefore do not seal against the outer diameter of the drill string.

Preferably each of the said two RCD seals can be selectively energised or de-energised by the respective introduction or removal of fluid from a respective cavity or chamber in fluid communication with a surface of the said two RCD seals and more preferably said respective cavity or chamber is in fluid communication with an outer surface of each of the said two RCD seals such that when fluid is pumped into said respective cavity or chamber, the said two RCD seals are forced inwards into contact with the tubular work string passing through the system housing to thereby form a seal in the annulus between the outer surface of the tubular work string and the inner throughbore of the system housing.

Typically, the said annular seal comprises an in use de-energised or deflated inner diameter which is greater than the outer diameter of the drill string which passes there through such that when the said annular seal in use is de-energised it allows the free movement of the drill string there through and therefore does not impede the movement there through and therefore does not seal against the outer diameter of the drill string.

In addition, the said annular seal typically comprises an in use energised or inflated inner diameter which matches the outer diameter of the drill string which passes there through such that when the said annular seal in use is energised it seals against the outer diameter of the drill string and therefore does not permit drilling fluid located in the annulus to pass through the throughbore of the annular seal in the upwards direction from downhole to up-hole when in the inflated state. Preferably the annular seal can be selectively energised or de-energised by the respective introduction or removal of fluid from a cavity or chamber in fluid communication with a surface of the said annular seal and more preferably said cavity or chamber is in fluid communication with an outer surface of the said annular seal such that when fluid is pumped into said cavity or chamber, the said annular seal is forced inwards into contact with tubular work string passing through the system housing to thereby form a seal in the annulus between the outer surface of the tubular work string and the inner throughbore of the system housing.

Preferably, the subsea RCD system further comprises a hydraulic fluid control system capable of controlling the pressure of fluid within the respective chamber and in particular within the two RCD seal chambers. More preferably, the hydraulic fluid control system is capable of controlling the pressure of fluid within the two RCD seal chambers such that said pressure is maintained at a positive delta pressure compared with the pressure of the wellbore fluids and/or drilling mud within the throughbore of the system housing. Typically, the hydraulic fluid control system comprises a pressure sensing mechanism to sense the pressure within the throughbore of the system housing and further comprises a hydraulic fluid source which is typically a hydraulic fluid accumulator capable of providing pressurised hydraulic fluid. More preferably, said hydraulic fluid control system comprises a fluid pressure signal transmission system which is preferably a wireless fluid pressure signal transmission system and most preferably is a Bluetooth™ wireless fluid pressure signal transmission system.

Preferably, the locking devices are configured such that in use, in the locked configuration, the respective two RCD seals and the said annular seal cannot move relative to the system housing and in the unlocked configuration the respective two RCD seals and the said annular seal can move relative to the system housing. This provides for a locking system wherein when the respective locking device is moved from the unlocked configuration to the locked configuration the respective two RCD seals and the said annular seal can move relative to the system housing.

Preferably the subsea RCD system is connected to the BOP via a suitable connection device and more preferably said suitable connection device comprises a flexible joint to permit flexible deviation of the subsea RCD system off the longitudinal axis of the BOP. Most preferably, said flexible joint comprises a Flex Joint™ offered by Oil States Industries of Heartlands, Scotland and is further preferably coupled to a LynxGrip™ HAR™ connector offered by Oil States Industries of Heartlands, Scotland.

The embodiments of the present invention have many advantages including great flexibility due to the modular nature of the two RCD seals and the said annular seal.

Embodiments of the present invention have the great advantage that a riser string does not need to be used unlike conventional RCD systems and therefore much smaller drilling rigs and platforms could be used than has hitherto been possible.

The accompanying drawings illustrate presently exemplary embodiments of the disclosure and together with the general description given above and the detailed description of the embodiments given below serve to explain, by way of example, the principles of the disclosure.

In the description that follows, like parts are marked throughout the specification and drawings with the same reference numerals, respectively. The drawings are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. The present invention is susceptible to embodiments of different forms. Specific embodiments of the present invention are shown in the drawings and herein will be described in detail, with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention and is not intended to limit the invention to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce the desired results.

The following definitions will be followed in the specification. As used herein, the term “wellbore” refers to a wellbore or borehole being provided or drilled in a manner known to those skilled in the art. The wellbore may be ‘open hole’ or ‘cased’, being lined with a tubular string. Reference to up or down will be made for purposes of description with the terms “above”, “up”, “upward”, “upper” or “upstream” meaning away from the bottom of the wellbore along the longitudinal axis of a work string toward the surface and “below”, “down”, “downward”, “lower” or “downstream” meaning toward the bottom of the wellbore along the longitudinal axis of the work string and away from the surface and deeper into the well, whether the well being referred to is a conventional vertical well or a deviated well and therefore includes the typical situation where a rig is above a wellhead and the well extends down from the wellhead into the formation, but also horizontal wells where the formation may not necessarily be below the wellhead. Similarly, ‘work string’ refers to any tubular arrangement for conveying fluids and/or tools from a surface into a wellbore. In the present invention, drill string is the preferred work string.

The various aspects of the present invention can be practiced alone or in combination with one or more of the other aspects, as will be appreciated by those skilled in the relevant arts. The various aspects of the invention can optionally be provided in combination with one or more of the optional features of the other aspects of the invention. Also, optional features described in relation to one embodiment can typically be combined alone or together with other features in different embodiments of the invention. Additionally, any feature disclosed in the specification can be combined alone or collectively with other features in the specification to form an invention.

Various embodiments and aspects of the invention will now be described in detail with reference to the accompanying figures. Still other aspects, features and advantages of the present invention are readily apparent from the entire description thereof, including the figures, which illustrates a number of exemplary embodiments and aspects and implementations. The invention is also capable of other and different embodiments and aspects and its several details can be modified in various respects, all without departing from the spirit and scope of the present invention.

Any discussion of documents, acts, materials, devices, articles and the like is included in the specification solely for the purpose of providing a context for the present invention. It is not suggested or represented that any or all of these matters formed part of the prior art base or were common general knowledge in the field relevant to the present invention.

Accordingly, the drawings and descriptions are to be regarded as illustrative in nature and not as restrictive. Furthermore, the terminology and phraseology used herein is solely used for descriptive purposes and should not be construed as limiting in scope. Language such as “including”, “comprising”, “having”, “containing” or “involving” and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents and additional subject matter not recited and is not intended to exclude other additives, components, integers or steps. In this disclosure, whenever a composition, an element or a group of elements is preceded with the transitional phrase “comprising”, it is understood that we also contemplate the same composition, element or group of elements with transitional phrases “consisting essentially of”, “consisting”, “selected from the group of consisting of”, “including” or “is” preceding the recitation of the composition, element or group of elements and vice versa. In this disclosure, the words “typically” or “optionally” are to be understood as being intended to indicate optional or non-essential features of the invention which are present in certain examples but which can be omitted in others without departing from the scope of the invention.

All numerical values in this disclosure are understood as being modified by “about”. All singular forms of elements, or any other components described herein including (without limitations) components of the assembly are understood to include plural forms thereof and vice.

BRIEF DESCRIPTION OF AND INTRODUCTION TO THE DRAWINGS

Embodiments of the present invention will now be described, by way of example only and with reference to the accompanying drawings, in which:—

FIG. 1 is a cross sectional side view of a first embodiment of a subsea rotating control device (RCD) system showing in its in use configuration for connection to the upper end of a BOP (albeit the drill string which would in use pass through the throughbore of the subsea RCD system is not shown);

FIG. 1A is a more detailed close up cross sectional side view showing section A of FIG. 1 , showing the pressure energised seals employed to seal the outer surface of the RCD outer housing to the inner surface of the system outer housing;

FIG. 1B is a more detailed close up cross sectional side view showing section B of FIG. 1 in more detail and which shows a series of staged dynamic seals which are employed to seal the lower end of the inner rotatable part of the RCD to the lower end of the stationary part of the RCD;

FIG. 1C is a cross sectional side view in more detail of section C of FIG. 1 and which shows an anti-rotation key which is mounted on an outer surface of a lower static annular packer seal housing in order to selectively rotationally lock the lower static annular packer seal housing to the inner bore of the system outer housing;

FIG. 1D is a cross sectional view of section D of FIG. 1 in more detail and which shows the inner bore 312U of the upper inflatable RCD packer 304 as being provided with a polyurethane (PU) sleeve 314U thereon in order to increase the lifespan of the upper inflatable RCD packer 304;

FIG. 1E is a cross sectional side view of the first embodiment of a rotating control device (RCD) of FIG. 1 positioned above a cross sectional side view of a lower static annular packer of FIG. 1 , where both the RCD and the lower static annular packer are ready to be attached to a running in tool and thus be run into the system outer housing of FIG. 1 in order to form the first embodiment of a subsea RCD system of FIG. 1 ;

FIG. 2 is a cross sectional side view of a second embodiment of a subsea RCD system for connection to the upper end of a BOP, where a drill pipe would normally be running through the throughbore of the subsea RCD system (but the drill pipe string is not shown in FIG. 2 ); and

FIG. 2A is a cross sectional side view of the second embodiment of a rotating control device (RCD) as shown in the subsea RCD system of FIG. 2 and is shown as positioned above a second embodiment of a lower static annual packer as also shown in the subsea RCD system of FIG. 2 , where both will be picked up by a retrieval tool mounted on a drill string and both will then be run into the throughbore of the system outer housing 10 in order to form the second embodiment of a subsea RCD system of FIG. 2 .

FIRST EMBODIMENT OF A SUBSEA RCD SYSTEM 1—FIG. 1

FIG. 1 shows a first embodiment of a subsea RCD system 1 and which comprises two main parts. The first main part is a system outer housing 10 (and which is also common to the second embodiment of a subsea RCD system 2 as will be described subsequently). The second part is a first embodiment of an RCD 300 and a lower static annular packer 190, where the RCD 300 and/or lower static annular packer 190 can be run into and/or retrieved from the inner throughbore of the system outer housing 10 by being latched onto by a retrieval tool (not shown) mounted within a drill string (not shown) or other suitable work string (not shown).

FIG. 1E shows the RCD 300 and lower static annular packer 190 as having been separated from the system outer housing 10 and therefore the RCD 300 and lower static annular packer 190 can be seen in greater clarity in FIG. 1E.

System Outer Housing 10—FIG. 1

The lower end of the system outer housing 10L is shown as being securely coupled to the upper end 14U of a suitable connection joint 14. A preferred connection joint 14 will provide some ability to flex the sealed connection or coupling between itself 14 and the lower end 10L of the system outer housing 10 in order to accommodate a drill string that is off longitudinal axis and a much preferred connection joint 14 is a Flex Joint offered by Oil States Industries of Heartlands, Scotland, but other suitable joints could also be used instead.

The lower end 14L of the connection joint 14 is coupled to the upper end 16U of a further suitable connector 16 and a preferred suitable connector 16 is a LynxGrip™ HAR™ offered by Oil States Industries of Heartlands, Scotland, but other suitable connectors could also be used instead.

The lower end 16L of the suitable connector 16 is connected to the upper end of a suitable blowout preventer (BOP) 18 (only shown in block diagram form in FIG. 1 and FIG. 2 ) which is provided in a secure mounting or connection to a wellhead (not shown) positioned at the subsea surface of a subsea wellbore (not shown).

During MPD drilling operations, a work string such as a drill string (not shown) is run into the wellbore through the throughbore 11 of the subsea RCD system 1 in order to drill the wellbore and it is the function of the subsea RCD system 1 to seal against the outer surface of the drill string in order to control the wellbore fluid and/or drilling mud returning from the wellbore and which is located in the annulus between the outer surface of the drill string and the inner surface 12 of the throughbore 11 of the subsea RCD system 1.

The system outer housing 10 is, in the embodiment shown in FIGS. 1 and 2 provided with a drilling mud returns outlet port 20 formed through its sidewall 15 at a location at or toward its lower end 10L (and importantly at a location below or upstream of the location at which the lower static annular packer 190 (which will be described subsequently) can seal against the outer surface of the drill string in order to seal the annulus) such that drilling mud returning back up from the wellbore up the annulus between the inner bore 12 of the lower end 10L of the system outer housing 10 and the outer surface of the drill string will be prevented from passing up past the lower static annular packer 190 and/or the rotating control device RCD 300 as will be subsequently described. Instead the wellbore fluids and/or drilling mud and cuttings will be able to exit out the drilling mud returns outlet port 20 and will then return back to the surface to the platform at the surface via a drilling mud returns hose (not shown) which is use will be connected to the drilling mud returns outlet port 20. In such a way, the subsea RCD system 1 can provide for riserless Managed Pressure Drilling (MPD) which provides an operator with great advantages, as will be subsequently described. Alternatively, the specific location of the drilling mud returns outlet port 20 could in one or more alternative embodiment(s) be moved further lower such that for example it or they were located in the sidewall of the connection joint 14 and such embodiments would have the advantage that the said drilling mud returns hose(s) (that connect(s) to the drilling mud returns outlet port(s) 20) would be static with respect to the connection joint 14 and thus wouldn't experience flex even if the lower end 10L of the system outer housing 10 flexed (with respect to the connection joint 14) when accommodating a drill string that is off longitudinal axis. In addition, the skilled person will understand that although FIGS. 1 and 2 only show one drilling mud returns outlet port 20, more than one drilling mud returns outlet port 20 may be provided in and around the sidewall of the lower end 10L or connection joint 14 as appropriate in order to accommodate two or more drilling mud returns hose(s). In addition, the diameter of the throughbore of the drilling mud returns outlet port(s) 20 can be varied depending upon the volume of drilling mud returns to be accommodated therein and which will flow there through.

Otherwise, the system outer housing 10 comprises a throughbore 11 having an inner throughbore surface 12 and outer diameter surface 13 and a sidewall 15 such that the system outer housing 10 is generally tubular along its longitudinal length. The sidewall 15 is generally sealed along its length (with the exception of the drilling mud returns outlet port 20 and some other hydraulic fluid inlets which will be subsequently described). Accordingly, pressurised fluids such as wellbore or reservoir fluids, drilling mud and drill cuttings located within the throughbore 11 and thus the rest of the joints 14, 16 and the BOP 18 are safely contained by and within the sidewall 15 of the system outer housing 10.

The system outer housing 10 further comprises a guide funnel 19 at its uppermost end and which comprises an outwardly tapering profile for ensuring guiding of the RCD 300 and lower static annular packer 190 into the system outer housing 10 when being run into the system outer housing 10, as will be described subsequently.

Rotatable Control Device (RCD)—300—FIG. 1E

The RCD 300 is shown in more detail in FIG. 1E and comprises two main parts, the first main part being a generally outer stationary part 342 which mainly comprises an RCD outer housing 308 which is generally cylindrical in nature.

The second main part of the RCD 300 is the generally inner rotatable part 340 of the RCD 300, albeit a significant portion being the upper portion 340U of the rotatable part 340 projects upwardly and outwardly from the stationary part 342 or the RCD outer housing 308.

The generally inner rotatable part 340 comprises an RCD inner housing 306 having an end cap 307 secured to its lower most end, where the end cap 307 comprises an axially extending spigot 307S and which in turn is provided with one or more (three are shown) staged dynamic seals 336 longitudinally spaced apart on the outer surface of the spigot 307S and which seal against the inner surface of the throughbore of the lower end 308L of the RCD outer housing 308. The staged dynamic seals 336 will act to prevent any fluid from passing up between the outside surface of the spigot 307S and the inner throughbore of the lower end 308L and also permit rotation to occur between the RCD inner housing 306 and the RCD outer housing 308. A plurality of bearings 332 are provided on the outer surface of the RCD inner housing 306 and in FIG. 1E it can be seen that there are two main sets of bearings 332, an upper most set 332U and a lower more set 332L and which in use will permit or allow the inner rotatable part 340 of the RCD 300 to rotate (whilst experiencing only minimal friction) with respect to the stationary part 342 of the RCD 300 and therefore the inner rotatable part 340 will be able to rotate with the drill string which passes through and is contained within the throughbore 11 of the subsea RCD system 1 when the pair of inflatable packers 304, 302 are inflated to seal against the outer surface of the drill string as will now be described.

The inner rotatable part 340 and in particular the RCD inner housing 306 comprises two recesses 301U and 301L provided on its inner throughbore surface 305. An upper inflatable RCD packer 304 is located in the upper recess 301U and accordingly the upper inflatable RCD packer 304 is trapped within the upper recess 301U and therefore cannot move longitudinally with respect thereto. However, the upper inflatable RCD packer 304 can be forced to move radially inwardly if required (e.g. when the operator requires to activate the upper inflatable RCD packer 304 to seal against the outer surface of the drill pipe string and therefore block the annulus therebetween at that location) by the operator pumping hydraulic fluid from a hydraulic accumulator 316 provided at the upper end 340U where the hydraulic fluid travels from the accumulator 316 via hydraulic fluid pathway 318 and where the hydraulic fluid pathway 318 is drilled through the RCD inner housing 306 until it communications with a chamber 304C via a hydraulic fluid port 318U. The chamber 304C is located behind, against or on the outer circumference of the upper inflatable RCD packer 304 such that when hydraulic fluid is pumped from the accumulator 316 via the hydraulic fluid pathway 318 via the hydraulic port 318U into the chamber 304C, the hydraulic fluid forces the upper inflatable RCD packer 304 to move radially inwardly to make contact with and thus seal against the outer surface of the drill pipe located in the throughbore 11. Moreover, and advantageously, the operator can control the pressure of the hydraulic fluid being pumped from the accumulator 316 such that the operator can increase that pressure to be a predetermined or certain amount greater than the wellbore pressure of the reservoir/wellbore fluids and/or drilling mud and cuttings within the throughbore 11 such that the inflatable upper RCD packer 304 provides a constant seal when required against the outer surface of the drill pipe string and thus prevents any drilling fluid or reservoir fluids from passing past the upper inflatable RCD packer 304 and thus prevents any reservoir fluids or drilling mud from exiting the throughbore 11 via the upper end 340U into the outer subsea environment. Instead, in use, the drilling mud and reservoir fluids are forced to exit the subsea RCD system 1 via a drilling mud returns outlet port 20 formed through the sidewall 15 of the system outer housing 10 at a location below (or upstream of) the upper inflatable RCD packer 304 (and moreover at a location below or upstream of the lower inflatable RCD packer 302 and the lower static annular packer 190) and such drilling muds can be returned to the platform or drilling rig at the surface of the water above the BOP 18 by means of a suitable hose connected between said drilling mud returns outlet port 20 and said platform or rig (not shown).

The radially inner most surface or throughbore 312U of the upper inflatable RCD packer 304 is provided with a sleeve 314U which is preferably formed of a hardwearing material such as Polyurethane (PU) in order to protect the more compliant material of the upper inflatable RCD packer which may be rubber or the like. Accordingly, it is the relatively harder wearing and longer lasting PU sleeve 314U which is in contact with the drill pipe string once the upper inflatable RCD packer 304 has been inflated.

The lower inflatable RCD packer 302 is located vertically below (and is therefore located upstream of) the upper inflatable RCD packer 304 and therefore it is in series or in line along the longitudinal axis 17 of the subsea RCD system 1. The lower inflatable RCD packer 302 is similarly located within a recess 301L formed in the RCD inner housing 306 in the inner rotatable part 340 and the lower inflatable RCD packer 302 also has a chamber 302C formed on its outer surface where the chamber 302C is also in fluid communication via hydraulic port 318L with the same hydraulic fluid pathway 318 as the upper inflatable RCD packer 304. Accordingly, actuation of the lower inflatable RCD packer 302 can be achieved at exactly the same time as actuation of the upper inflatable RCD packer 304 by pumping hydraulic fluid from the accumulator 316.

The subsea RCD system 1 further comprises a hydraulic fluid control system to control operation of the accumulator 316, where the hydraulic fluid control system comprises a pressure transducer and combined Bluetooth™ transmitter 22, where the pressure transducer 22 sends the pressure of fluids contained within the throughbore 11 and the Bluetooth™ transmitter 22 sends that sensed pressure reading to a Bluetooth™ receiver 323 and the hydraulic fluid control system can then receive that sensed pressure signal from the Bluetooth™ receiver 323 and can then instruct the hydraulic accumulator 316 accordingly, depending on whether additional hydraulic fluid pressure is required to be provided into the chambers 304C, 302C in order to provide a greater seal between the upper 304 and lower 302 inflatable RCD packers or whether they should be deflated (in which case the hydraulic fluid pressure should be reduced to withdraw the hydraulic fluid from both chambers 304C, 302C) if the fluid pressure should be reduced in order to avoid damaging the packers 304, 302 or indeed if they should be moved radially outwards so that they are no longer in contact with the drill string if for example the RCD 300 is to be retrieved from the RCD system 1 (for example in order to be replaced by a new RCD 300 having new seals 304, 302 as will be described subsequently).

An anti-rotation key 352 is provided towards the upper end of the RCD housing 308, where the anti-rotation key 352 is arranged to be located within a slot formed in the outer surface of the RCD outer housing 308 and where the key 352 is biased outwardly by a biasing means such as one or more springs. The key 352 is provided at a specific location on the outside of the RCD outer housing 308 such that it will be possible to be aligned with an axially extending slot formed on the inner surface 12 of the system outer housing 10 such that when the key 352 aligns with said slots in the system outer housing 10, it will be biased into that slot and will therefore assist in preventing rotation of the RCD outer housing 308 (and thus the rest of the stationary part 342) occurring relative to the system outer housing 10. However, the keys 352 are also provided with tapered edges at their upper and lower most ends such that pulling upon the RCD 300 (for example by means of a retrieval profile provided on the outer surface of a retrieval tool included in a drill string (not shown) which can locate in a retrieval profile 310 formed on the inner surface 305 of the inner rotatable part 340 of the RCD 300 and therefore pulling upwards by the drill string can pull the RCD 300 upwards out of the system outer housing 10 and such pulling will overcome the biasing action of the springs of the key 352 and therefore the RCD 300 can be pulled upwards out of the system outer housing 10.

An arrangement of pressure energised seals 326 is further provided on the outer surface of the RCD outer housing 308 and in particular there is preferably provided a lower set of pressure energised seals 326L at or towards the lower end of the RCD outer housing 308 and an upper set of pressure energised seals 326U provided at or towards the upper end of the RCD outer housing 308. The seals 326 have a radially inner face which is in contact with a fluid conduit 328 formed at least through the RCD outer housing 308 between the upper 326U and the lower 326L seals. The fluid conduit 328 is further in fluid communication with a hydraulic port 330 formed through the sidewall of the RCD outer housing 308.

The fluid port 330 has a dual function, however, in that it also provides an aperture into which a locking dog 68 can be moved into. The locking dog is mounted on the outer surface of the system outer housing 10 within an aperture formed through the sidewall 15 of the system outer housing 10, where the locking dog 68 can be moved radially inwards (in order to lock into the fluid port 330) and can be moved radially outwards (to unlock from the fluid port 330) and therefore to release the RCD 300 such that it can be retrieved from the system outer housing 10. In addition, the locking dog 68 has a fluid port formed longitudinally through its centre such that hydraulic fluid can be pumped therethrough from a hydraulic fluid supply line 65U which in turn connects with a flying lead which is connected to the BOP 18. Accordingly, signals sent to the BOP 18 can instruct the BOP 18 to pump hydraulic fluid into (or pump out of) the supply line 65U and therefore into or out of the fluid conduit 328 in order to actuate/energise the pressure energise seals 326 or de-actuate/de-energise the pressure energised seals 326 in order to either seal or unseal the RCD 300 and in particular the outer surface thereof with respect to the inner surface of the system outer housing 10 such that no unwanted wellbore fluids can flow from the throughbore 11 up between the outside of the RCD outer housing 308 and the inner throughbore of the system outer housing 10.

Lower Static Annual Packer 190

The lower static annual packer 190 comprises a housing 200 which is generally cylindrical and which contains a throughbore 211 and recess within the inner surface 205 of the throughbore 211, where the recess 201 contains the inflatable lower static annular packer seal 202 in such a manner that the packer seal 202 is held captive within the recess 201 such that is cannot move axially. However, it can be forced radially inwards to grip its inner surface 203 against the outer surface of the drill string by pumping hydraulic fluid into fluid conduit 218 via fluid and locking port 231 such that the hydraulic fluid creates a chamber 202C around the outer surface 2020 of the packer seal 202 such that the packer seal 202 is forced radially inwardly in order to grip its inner surface 203 against the outer surface of the drill pipe string.

An anti-rotation key 252 is also provided on the outer surface of the packer housing 200 and is adapted to locate within a longitudinal slot formed at a suitable location on the inner surface 12 of the system outer housing 10 in order to prevent rotation of the lower static annual packer 190 within the system outer housing 10.

A set of pressure energised seals 226L is provided at or towards the lower end of the packer seal housing 200 and an upper set 226U of pressure energised seals is provided at or towards the upper end of the packer seal housing 200, where both pressure energised seals 226 are actuated by means of hydraulic fluid being pumped into fluid conduit 228 which connects both sets of pressure energised seals 226 via a fluid and locking port 230.

The inner surface 205 of the packer seal 200 is further provided with a retrieval profile 210 preferably at its upper end in order to permit a suitable retrieval profile (not shown) formed on the outer surface of a drill pipe string (not shown) to land therein and retrieve the lower static annual packer 190 should that be required and/or to run in a new lower static annular packer 190 instead. In addition, because the lower static annual packer is located in use below the RCD 300, both the lower static annual packer 190 and the RCD 300 can be retrieved from or run in to the throughbore 11 of the system outer housing 10 together by locating the retrieval profile of the drill pipe string into the retrieval profile 210 of the lower static annular packer 190 and sitting the RCD 300 on top of the lower annular static packer 190 around the drill pipe string such that both can be run into or retrieved from the throughbore 11 of the system outer housing 10 at the same time.

Once the lower static annular packer 190 is located within the system outer housing 10, it can be locked in place by means of a lowermost first set of locking dogs 64L being actuated to move radially inwards such that they locate within the fluid and locking port 230 and further locked in place by means of a lowermost second set of locking dogs 64R being actuated to move radially inwards such that they locate within the fluid and locking port 231. Hydraulic fluid can then be pumped through the throughbore of the locking dog 64L via fluid conduit 65L via the flying lead 70 from the BOP 18 in order to actuate the pressure energised seals 226.

Furthermore, when the operator requires to actuate the inflatable lower static annular packer seal 202, the operator can instruct the BOP 18 to pump hydraulic fluid from the BOP 18 through the flying lead 70 and through the throughbore of the second set of locking dogs 64R (once they have been moved radially inwards in order to lock into the fluid locking port 231) such that the hydraulic fluid flows from the port 231 via the fluid conduit 218 into the space 2020 between the outer surface of the packer seal 202 and the inner surface of the recess 201 in order to create the chamber 202C such that the packer seal 202 is inflated in order to move it radially inwards to compress against the outer surface of the drill pipe. The operator would likely wish to actuate or inflate the lower static annular packer seal 202 in circumstances where the RCD 300 can no longer adequately seal against the outer surface of the drill pipe and therefore in such a circumstance, either or both of the upper 304 or lower 302 RCD packers need to be replaced. In that circumstance, the seals 304, 302 on the RCD 300 would be deflated but only after the lower static annular packer seal 202 has been inflated such that the wellbore fluids located below the lower static annual packer 190 are contained by the inflated lower static annual packer seal 202. The RCD 300 can then be unlatched from its locking dog 68 and can then be retrieved from the wellbore by a retrieval tool landing its profile in the landing profile 310.

It should be noted that the lower annual packer 190 is a static packer in that, whilst it is actuable and inflatable to move it radially inwards to seal against the outer surface of the drill pipe located in its throughbore 211, it is a static packer 190 in that it is not intended to be able to rotate relative to the subsea outer housing 10. The reason for this is that if the lower annual packer 190 is actuated to seal against the outer surface of the drill string then the operator will not be drilling and will therefore not be rotating the drill pipe because the lower annual packer 190 is likely to be the only annular seal against the outer surface of the drill pipe within the subsea RCD system because the RCD 300 is likely to be out of operation or is being replaced. However, the skilled person will understand that the lower annual packer 190 could be modified such that it is provided for example with bearings in order to allow the inflatable lower annual packer seal 202 to rotate with the drill pipe string. In addition, the subsea RCD system could be modified such that there is provided two or more inflatable lower annual packer seals 202 in series such that there is redundancy in place.

Additionally, or alternatively, the inflatable lower static annular packer seal 202 can be provided with a sleeve such as a polyurethane sleeve (not shown) on its inner throughbore surface in order to provide additional life span and durability in a similar manner to the PU sleeve 312 provided on either or both of the upper 304 and lower 302 inflatable RCD packers.

Accordingly, in use, both of the upper 304 and lower 302 inflatable RCD seals can be used for pressure control of the drilling mud and wellbore fluids located in the throughbore 11 for both drilling operations (i.e. whilst the drill string is rotating) and also stripping operations (i.e. whilst the drill string is tripping into or out of the wellbore) and moreover the lower static annual packer 190 can be used to provide pressure control of the wellbore fluids and drilling mud located within the throughbore 11 for stripping operations where the drill string is being tripped into or pulled out of the wellbore.

Sequence of Operations for Installation of Subsea RCD System 1

1. The lower end of the subsea RCD system 1 is typically attached to the upper end of the flex connection joint 14 and the suitable connection 16 at the surface of the sea on the platform or drilling rig.

2. A retrieval tool is included in a work string such as a drill string at the surface of the sea on the platform or drilling rig. The retrieval profile on the retrieval tool is coupled to and connected into the retrieval profile 210 provided within the lower static annular packer 190 or more preferably via the retrieval profile 310 provided within the RCD 300 such that the subsea RCD system 1 plus connections 14, 16 are hanging off the retrieval tool provided within the drill string. The drill string is then lowered through the BOP 18 into the wellbore from the platform or drilling rig at the surface of the sea until the connection 16 makes contact with the BOP 18 and is secured and sealed thereto.

3. An ROV or other suitable means is used to connect the flying lead 70 from the BOP 18 to the system outer housing 10 such that the hydraulic fluid supply from the flying lead is connected into the locking dogs 64L, 64R via their respective lines 65L. 65R.

4. The retrieval tool within the drill string is de-actuated such that it disconnects from the retrieval profile 310 (or 210 as appropriate) and the drill string is pulled someway back up to the surface as far as required in order to remove the retrieval tool from the drill string. Alternatively, if the drill string can drill with the retrieval tool still in place in the drill string then this step can be skipped.

5. The upper 304 and lower 302 inflatable RCD packers are inflated by actuation of the hydraulic fluid control system which instructs the actuator 316 to provide pressurised hydraulic fluid to the chambers 302C and 304C to the required fluid pressure such that said pressure is greater that the drilling mud and wellbore fluid pressure located within the throughbore 11 (as sensed by the pressure transducer and Bluetooth transmitter 22). It should be noted that both upper 304 and lower 302 inflatable RCD packers are inflated so that the seals formed thereby against the drill pipe string are duplicated such that there is back up in case one of them fails. Once the upper 302 and lower 304 RCD packers are inflated, the operator can then commence managed pressure drilling (MPD) operations because the inner rotatable part 340 can now rotate with the drill pipe string and furthermore the drill pipe string can be moved downwards through the subsea RCD system 1, with the drill pipe joints passing through the seals 304, 302 in a stripping operation. In addition, the embodiments of the present invention have the great advantage that the hydraulic control system can automatically adjust the pressure exerted upon the drill string by the upper 304 and lower 302 inflatable packer seals and it can increase or decrease the force as required in order to ensure that an appropriate positive delta pressure is maintained between the force being applied and the pressure of the wellbore fluids and drilling mud located within the throughbore 11.

6. Should either or both of the upper 304 and lower 302 RCD inflatable packer seals require to be replaced and if step 4 was followed, then the drilling operations will be halted and the drill string is pulled back to surface in order that a retrieval tool can be included in the drill string at surface.

7. The retrieval/running tool is then run into the throughbore 11 until it aligns with the retrieval profile 310 within the RCD 300. The retrieval tool is then actuated to latch inside the retrieval profile 310.

8. The lower static annular packer seal 202 is then inflated to seal against the outer surface of the drill pipe.

9. The upper most set of locking dogs 68 can then be retracted radially outwards such that they no longer engage/lock within the fluid port/locking port 330 of the RCD 300. Alternatively, the operator can instruct the hydraulic fluid control system to de-pressurise and therefore deflate the upper 304 and lower 302 inflatable RCD packers. Such an action will also deflate the upper 304 and lower 302 inflatable RCD packers, such that all of the annular sealing is being provided by the inflated lower static annular packer seal 202. Alternatively, the operator can instruct the hydraulic fluid control system to de-pressurise and therefore deflate the upper 304 and lower 302 inflatable RCD packers, such that all of the annular sealing is being provided by the inflated lower static annular packer seal 202.

10. The RCD 300 can then be retrieved or pulled back to the surface on the drill pipe string, with the drill pipe joints being stripped through the inflated and sealed lower static annular packer seal 202.

11. The old/worn RCD 300 can be replaced with a new RCD 300 and it can be run back in on the running tool of the drill pipe string by means of its retrieval profile 310 being engaged by the running tool. The new RCD 300 will be run in until it reaches its in use location and the upper set of locking dogs 68 will engage in the new RCD 300 such that the new RCD 300 is locked in placed by the locking dogs 68. The retrieval tool can be de-actuated and the upper 304 and lower 302 RCD packers can be inflated in order to seal against the outer surface of the drill pipe. The lower static annular packer seal 202 can then be deflated. The retrieval tool can be pulled back to the surface if needs be, removed from the drill string and the drill string can then be run back into the hole through the subsea RCD system 1 and drilling operations can be commenced.

12. Should both of the lower static annular packer 190 and the RCD 300 need to be recovered back to the surface, then the running tool can be included in the drill string and the drill string can be run into the subsea RCD system 1 until the running tool is aligned with the retrieval profile 210 and the retrieval profile can latch into the retrieval profile 210 of the lower static annular packer 190. Once it is locked in place, the next stage occurs.

13. Both sets of locking dogs 68, 64 are retracted radially outwards such that neither the RCD 300 nor the lower static annular packer 190 are locked with respect to the system outer housing 10. The RCD 300 and the lower static annular packer 190 can then be recovered back to the surface by pulling the upper end of the drill string upwards.

14. The old RCD 300 and lower static annular packer 190 can be replaced at the surface with respective new RCD 300 and lower static annular packer 190 and can be run back down into the system outer housing 10 on the retrieval tool of the drill string.

15. Both sets of locking dogs 64, 68 are then actuated to lock into their respective fluid and locking ports 230, 231; 330.

16. The retrieval tool can then be retrieved back to the surface by pulling up on the drill string. The retrieval tool can be removed from the drill string if required and drilling operations can then be commenced again once the upper RCD packer 304 and the lower ECD packer 302 have been inflated.

Embodiments of the present invention therefore provide a subsea RCD system 1 incorporating removable annular seals 304, 302, 202. In addition, embodiments of the present invention provide a pair of removable rotating (RCD) inflatable packers 304, 302 which can be inflated to seal on the drill string while drilling. The packers 304, 302 are inflated by means of an accumulator 316 attached to the RCD 300. The wellbore pressure 11 is continuously monitored, with the pressure reading transmitted to the accumulator 316 via a Bluetooth™ transmitter/receiver system to allow the packer 304, 302 actuation pressure to maintain a constant positive delta above that of the wellbore pressure 11. It should however be noted that other suitable wireless signal or data transmission systems can be used and indeed a suitable wire or cable could be used instead in conjunction with a suitable slip ring arrangement as will be understood by the skilled reader.

Embodiments of the present invention therefore also provide a further single inflatable static packer in the form of the lower static annular static packer 190 and this is included in order to be able to seal on the drill string whilst stripping operations are conducted.

The various packers, 304, 302, 202 are installed in their respective housings which can have the form of cartridges which are landed and locked within the bore 11 of the subsea RCD system 1. These housings/cartridges can be run/retrieved to replace the respective seals therein 304; 302; 202 without the need to retrieve the full subsea RCD system or unit 1. This greatly enhances the serviceability and maintainability of the subsea RCD system 1 as these wearable seals/parts 304; 302; 202 can be quickly/easily replaced with the minimum of hassle/downtime.

The subsea RCD system 1 preferably includes an Oil States LynxGrip™ HAR™ connector in order to connect the subsea RCD system 1 to the BOP 18 and further preferably includes an Oil States FlexJoint™ to dampen the operational loads transferred into the BOP 18.

An alternative second embodiment of a subsea RCD system 2 is shown in FIG. 2 . The second embodiment of subsea RCD system 2 comprises the same system outer housing 10 as that hereinbefore described, along with the same lower locking dog 64L, 64R arrangement and associated hydraulic fluid supply lines 65L; 65R and same upper locking dog arrangements 68 along with the same hydraulic fluid supply line 69 and the same drilling mud return outlet port 20 and the same flex connection joint 14 and suitable connection 16 for connection to the BOP 18 and the same flying lead 70 along with the same guide funnel 19 for ensuring guiding of the RCD 2300 and lower static annular packer 190 into the system outer housing 10.

Indeed, in the second embodiment of subsea RCD system 2, the lower static annular packer 190 is the same as that used in the first embodiment of subsea RCD system 1.

Moreover, the main difference between the second embodiment 2 and the first embodiment 1 of subsea RCD systems is with the RCD 2300 compared to the RCD 300. However, similar components between the RCD 2300 and the RCD 300 are indicated with the same reference numerals except with the addition of 2000 to that used in the second embodiment 2. The main difference between the two embodiments 1, 2 is that with the RCD 2300, the inner rotatable part 2340 is now wholly contained within the stationary part 2342. Indeed, the inner rotatable part 2340 now comprises both the upper inflatable RCD 2304 and the lower inflatable RCD packer 2302 being wholly contained within the inner rotatable part 2340 which comprises the RCD inner housing 2306 which in turn now comprises at its upper end a set of staged dynamic seals 2336U and at its lower end a further set of staged dynamic seals 2336L, such that the RCD inner housing 2306 is now rotatable within the RCD outer housing 2308 by virtue of an upper 2332U and lower 2332L sets of bearings. Consequently, the upper end 2300U of the RCD 2300 now no longer rotates and therefore the accumulator 2316 which is mounted at the upper end 2300U is now stationary and thus the Bluetooth™ transmitter 22 and Bluetooth™ receiver 2323 could be replaced more straightforwardly with a wired cable because no slip ring would now be required. In all other respects, the RCD 2300 will be operated in a similar manner as already hereinbefore described to the RCD 300. In addition, the lower static annular packer 2190 of FIG. 2A and FIG. 2 is operated in exactly the same manner as the lower static annular packer 190 of the first embodiment 1.

Modifications and improvements may be made to the embodiments hereinbefore described without departing from the scope of the invention. 

1. A subsea rotating control device (RCD) system adapted to permit a tubular work string to pass there through such that there is an annulus created between the inner throughbore of subsea rotating control device (RCD) system and the outer surface of the tubular work string, the subsea rotating control device (RCD) system comprising: a system housing comprising a throughbore; an upper end; and a lower end adapted for connection with a BOP of a wellhead; and the subsea RCD system further comprising:— at least two RCD seals arranged for selective mounting within the system housing and which are selectively actuable between an unsealed configuration in which the at least two RCD seals are radially outwardly retracted and a sealed configuration in which the at least two RCD seals are radially inwardly extended; and at least one annular seal arranged for selective mounting within the system housing below the at least two RCD seals, wherein the said at least one annular seal is selectively actuable between an unsealed configuration in which the said at least one annular seal is radially outwardly retracted and a sealed configuration in which the said at least one annular seal is radially inwardly extended.
 2. The subsea rotating control device (RCD) system according to claim 1, wherein the at least two RCD seals are inflatable such that they can be inflated into the sealed configuration and deflated into the unsealed configuration.
 3. The subsea rotating control device (RCD) system according to claim 1, wherein the at least one annular seal is inflatable such that it can be inflated into the sealed configuration and deflated into the unsealed configuration.
 4. The subsea rotating control device (RCD) system according to claim 1, wherein the system housing comprises a throughbore and a wellbore fluid and/or drilling mud returns port formed through a sidewall in fluid communication with the throughbore of the system housing.
 5. The subsea rotating control device (RCD) system according to claim 4, wherein the port permits wellbore fluid and/or drilling mud located in the throughbore of the subsea rotating control device (RCD) system below the lowermost of the at least two RCD seals and/or the at least one annular seal to exit the throughbore and return to the surface.
 6. The subsea rotating control device (RCD) system according to claim 1, wherein the at least two RCD seals are capable of being locked within the throughbore by at least one locking device.
 7. The subsea rotating control device (RCD) system according claim 6, wherein the at least one annular seal is capable of being locked within the throughbore by at least one locking device.
 8. The subsea rotating control device (RCD) system according to claim 7, wherein, each of the at least two RCD seals and the at least one annular seal comprise their own respective locking device.
 9. The subsea rotating control device (RCD) system according to claim 8, wherein each of the at least two RCD seals and the at least one annular seal can be separately and selectively locked and unlocked as required by actuation of their own respective locking device in such a manner to permit one of them to be locked within the throughbore and the other of them to be run into and/or retrieved from the throughbore of the system housing.
 10. The subsea rotating control device (RCD) system according to claim 9, wherein each of the said at least two RCD seals are provided within an RCD housing, and the said at least one annular seal is provided within a separate housing from that of the at least two RCD seals.
 11. The subsea rotating control device (RCD) system according to claim 10, wherein the at least two RCD seals are rotateably mounted within said RCD housing by at least one bearing mechanism.
 12. The subsea rotating control device (RCD) system according to claim 1, wherein each of the said at least two RCD seals and the at least one annular seal comprises a retrieval means to permit running in and/or retrieval of the respective each of the said at least two RCD seals and the said at least one annular seal.
 13. The subsea rotating control device (RCD) system according to claim 10, wherein each said seal housing comprises a locking means into which a respective locking device can engage in order to lock said seal housing of said respective seal within the throughbore of the system housing where each said locking device is mounted on the system housing.
 14. The subsea rotating control device (RCD) system according to claim 13, wherein each said locking device can be actuated between a radially inwardly projecting configuration and a retracted configuration such that they do not project into said locking means of the respective seal housing.
 15. The subsea rotating control device (RCD) system according to claim 13, wherein each said locking device is remotely actuatable between the radially inwardly projecting or locked configuration and the retracted or unlocked configuration, allowing for remote activation of each of the locking devices by an operator from the surface.
 16. The subsea rotating control device (RCD) system according to claim 1, wherein at least one of the two RCD seals and the said annular seal device can be:— i) run into the throughbore of the system housing, typically through an upper end of the system housing; and ii) locked to the system housing within the throughbore of the system housing.
 17. The subsea rotating control device (RCD) system according to claim 1, wherein at least one of the said two RCD seals and the said annular seal are capable of being unlocked from and retrieved from the throughbore of the system housing, by pulling it upwards through the throughbore of the system housing and further pulling it upwards through the upper end of the system housing into the surrounding subsea environment on a workstring.
 18. The subsea rotating control device (RCD) system according to claim 17, wherein the at least two RCD seals can be retrieved and run into the throughbore either on its own by a running/retrieval tool or can be retrieved and run into the throughbore with the at least one annular seal.
 19. The subsea rotating control device (RCD) system according to claim 1, wherein the at least two RCD seals comprise an outer RCD housing and said at least two RCD seals are mounted within and are rotatable with respect to the outer RCD housing.
 20. The subsea rotating control device (RCD) system according to claim 19, wherein the two RCD seals further comprise one or more bearings to couple them to the RCD housing such that the two RCD seals are rotatable on the bearing with respect to the stationary outer RCD housing such that the said each respective RCD seal seals against and is rotatable with the work string which passes through the throughbore of the system housing.
 21. The subsea rotating control device (RCD) system according to claim 20, wherein each of the upper and lower RCD seals is formed from a resilient material and which is inflatable such that when in an inflated state has an inner diameter which is a friction fit such that it comprises an inner diameter that matches the outer diameter of the work string such that each of the upper and lower RCD seals are forced against the outer surface of the work string and seals against the outer surface of the drill string such that it does not permit drilling fluid or other well fluids located in the annulus to pass through the throughbore of the two RCD seals in the upwards direction from downhole to up-hole when in the inflated state.
 22. The subsea rotating control device (RCD) system according to claim 20, wherein the said two RCD seals comprise an in use de-energised or deflated inner diameter which is greater than the outer diameter of the drill string which passes there through such that when the said two RCD seals in use are de-energised, they allow the free movement of the drill string there through and therefore do not impede the movement there through and therefore do not seal against the outer diameter of the drill string.
 23. The subsea rotating control device (RCD) system according to claim 22, wherein each of the said two RCD seals can be selectively energised or de-energised by the respective introduction or removal of fluid from a respective cavity or chamber in fluid communication with a surface of the said two RCD seals and more preferably said respective cavity or chamber is in fluid communication with an outer surface of each of the said two RCD seals such that when fluid is pumped into said respective cavity or chamber, the said two RCD seals are forced inwards into contact with the tubular work string passing through the system housing to thereby form a seal in the annulus between the outer surface of the tubular work string and the inner throughbore of the system housing.
 24. The subsea rotating control device (RCD) system according to claim 1, wherein the said annular seal comprises an in use de-energised or deflated inner diameter which is greater than the outer diameter of the work string which passes there through such that when the said annular seal in use is de-energised it allows the free movement of the work string there through and therefore does not impede the movement there through and therefore does not seal against the outer diameter of the work string and the said annular seal further comprises an in use energised or inflated inner diameter which matches the outer diameter of the work string which passes there through such that when the said annular seal in use is energised it seals against the outer diameter of the work string and therefore does not permit drilling fluid located in the annulus to pass through the throughbore of the annular seal in the upwards direction from downhole to up-hole when in the inflated state.
 25. The subsea rotating control device (RCD) system according to claim 24, wherein the annular seal can be selectively energised or de-energised by the respective introduction or removal of fluid from a cavity or chamber in fluid communication with a surface of the said annular seal and more preferably said cavity or chamber is in fluid communication with an outer surface of the said annular seal such that when fluid is pumped into said cavity or chamber, the said annular seal is forced inwards into contact with tubular work string passing through the system housing to thereby form a seal in the annulus between the outer surface of the tubular work string and the inner throughbore of the system housing.
 26. The subsea rotating control device (RCD) system according to claim 23, wherein the subsea RCD system further comprises a hydraulic fluid control system capable of controlling the pressure of fluid within the respective chamber and in particular within the two RCD seal chambers.
 27. The subsea rotating control device (RCD) system according to claim 26, wherein the hydraulic fluid control system is capable of controlling the pressure of fluid within the two RCD seal chambers such that said pressure is maintained at a positive delta pressure compared with the pressure of the wellbore fluids and/or drilling mud within the throughbore of the system housing.
 28. The subsea rotating control device (RCD) system according to claim 26, wherein the hydraulic fluid control system comprises a pressure sensing mechanism to sense the pressure within the throughbore of the system housing and further comprises a hydraulic fluid source capable of providing pressurised hydraulic fluid.
 29. The subsea rotating control device (RCD) system according to claim 28, wherein said hydraulic fluid control system comprises a wireless fluid pressure signal transmission system.
 30. The subsea rotating control device (RCD) system according to claim 16, wherein the locking devices are configured such that in use, in the locked configuration, the respective two RCD seals and the said annular seal cannot move relative to the system housing and in the unlocked configuration the respective two RCD seals and the said annular seal can move relative to the system housing. 